Supplemental Oil And Gas Disclosures

12 Months Ended

Dec. 31, 2018

Supplemental Oil and Gas Disclosures [Abstract]

SUPPLEMENTAL OIL AND GAS DISCLOSURES

(UNAUDITED)

Our oil and gas operations are substantially located in the United States. The capitalized costs at year end and costs incurred during the year were as follows:


	2018		2017		2016
	(In thousands)
Capitalized costs:
Proved properties	$	6,018,568	$	5,712,813	$	5,446,305
Unproved properties	330,216		296,764		314,867
	6,348,784		6,009,577		5,761,172
Accumulated depreciation, depletion, amortization, and impairment	(5,124,257)		(4,996,696)		(4,900,304)
Net capitalized costs	$	1,224,527	$	1,012,881	$	860,868
Cost incurred:
Unproved properties acquired	$	57,430	$	47,029	$	21,675
Proved properties acquired	15,158		47,638		564
Exploration	15,907		14,811		17,325
Development	280,692		160,941		80,582
Asset retirement obligation	(7,629)		(3,613)		(30,906)
Total costs incurred	$	361,558	$	266,806	$	89,240

The following table shows a summary of the oil and natural gas property costs not being amortized at December 31, 2018, by the year in which such costs were incurred:


	2018		2017		2016		2015 and Prior		Total
	(In thousands)
Unproved properties acquired and wells in progress	$	60,372	$	46,986	$	21,947	$	200,911	$	330,216

Unproved properties not subject to amortization relates to properties which are not individually significant and consist primarily of lease acquisition costs. The evaluation process associated with these properties has not been completed and therefore, the company is unable to estimate when these costs will be included in the amortization calculation.

The results of operations for producing activities are as follows:


	2018		2017		2016
	(In thousands)
Revenues	$	429,119	$	347,285	$	282,742
Production costs	(131,328)		(113,344)		(103,568)
Depreciation, depletion, amortization, and impairment	(132,923)		(101,326)		(274,155)
	164,868		132,615		(94,981)
Income tax (expense) benefit	(42,915)		(52,078)		32,696
Results of operations for producing activities (excluding corporate overhead and financing costs)	$	121,953	$	80,537	$	(62,285)

Estimated quantities of proved developed oil, NGLs, and natural gas reserves and changes in net quantities of proved developed and undeveloped oil, NGLs, and natural gas reserves were as follows:


	Oil Bbls	NGLs Bbls	Natural Gas Mcf	Total MBoe
	(In thousands)
2016
Proved developed and undeveloped reserves:
Beginning of year	16,735	37,687	484,868	135,233
Revision of previous estimates ⁽¹⁾	(549)	(2,473)	(31,670)	(8,300)
Extensions and discoveries	1,816	1,588	13,720	5,690
Infill reserves in existing proved fields	663	2,724	24,704	7,504
Purchases of minerals in place	114	43	630	262
Production	(2,974)	(5,014)	(55,735)	(17,277)
Sales	(109)	(73)	(30,938)	(5,338)
End of year	15,696	34,482	405,579	117,774
Proved developed reserves:
Beginning of year	14,679	31,218	416,395	115,296
End of year	12,724	28,502	347,121	99,079
Proved undeveloped reserves:
Beginning of year	2,056	6,469	68,473	19,937
End of year	2,972	5,980	58,458	18,695
2017
Proved developed and undeveloped reserves:
Beginning of year	15,696	34,482	405,579	117,774
Revision of previous estimates ⁽¹⁾	730	4,325	38,330	11,444
Extensions and discoveries	2,235	4,520	49,321	14,975
Infill reserves in existing proved fields	1,632	5,779	52,270	16,123
Purchases of minerals in place	2,019	1,197	15,313	5,768
Production	(2,715)	(4,737)	(51,260)	(15,996)
Sales	(84)	(80)	(903)	(314)
End of year	19,513	45,486	508,650	149,774
Proved developed reserves:
Beginning of year	12,724	28,502	347,121	99,079
End of year	14,862	33,358	388,446	112,961
Proved undeveloped reserves:
Beginning of year	2,972	5,980	58,458	18,695
End of year	4,651	12,128	120,204	36,813
2018
Proved developed and undeveloped reserves:
Beginning of year	19,513	45,486	508,650	149,774
Revision of previous estimates	180	(1,368)	(17,859)	(4,165)
Extensions and discoveries	3,250	5,149	75,806	21,033
Infill reserves in existing proved fields	1,898	2,795	23,778	8,656
Purchases of minerals in place	701	856	6,897	2,707
Production	(2,874)	(4,925)	(55,627)	(17,070)
Sales	(110)	(197)	(5,682)	(1,254)
End of year	22,558	47,796	535,963	159,681
Proved developed reserves:
Beginning of year	14,862	33,358	388,446	112,961
End of year	15,192	33,515	377,216	111,576
Proved undeveloped reserves:
Beginning of year	4,651	12,128	120,204	36,813
End of year	7,366	14,281	158,747	48,105

_________________________

1.Natural gas revisions of previous estimates decreased primarily due to a decline in natural gas prices.

Estimates of oil, NGLs, and natural gas reserves require extensive judgments of reservoir engineering data. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth in this report is, therefore, subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static, and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves, nor of estimated future cash flows.

The standardized measure of discounted future net cash flows (SMOG) was calculated using 12-month average prices and year end costs adjusted for permanent differences that relate to existing proved oil, NGLs, and natural gas reserves. Future income tax expenses consider the Tax Act statutory tax rates. SMOG as of December 31 is as follows:


	2018		2017		2016
	(In thousands)
Future cash flows	$	3,980,369	$	3,347,396	$	2,030,925
Future production costs	(1,479,744)		(1,308,244)		(861,625)
Future development costs	(442,984)		(369,560)		(173,446)
Future income tax expenses	(307,916)		(234,152)		(141,752)
Future net cash flows	1,749,725		1,435,440		854,102
10% annual discount for estimated timing of cash flows	(766,047)		(628,270)		(335,892)
Standardized measure of discounted future net cash flows relating to proved oil, NGLs, and natural gas reserves	$	983,678	$	807,170	$	518,210

The principal sources of changes in the standardized measure of discounted future net cash flows were as follows:


	2018		2017		2016
	(In thousands)
Sales and transfers of oil and natural gas produced, net of production costs	$	(297,791)	$	(239,953)	$	(173,920)
Net changes in prices and production costs	120,062		236,126		(94,026)
Revisions in quantity estimates and changes in production timing	(33,282)		87,239		(51,979)
Extensions, discoveries, and improved recovery, less related costs	234,172		102,965		84,738
Changes in estimated future development costs	19,535		(5,194)		70,976
Previously estimated cost incurred during the period	63,557		36,044		16,602
Purchases of minerals in place	23,416		51,686		2,652
Sales of minerals in place	(5,004)		(1,447)		(17,248)
Accretion of discount	89,753		57,517		69,069
Net change in income taxes	(31,674)		(33,389)		44,241
Other—net	(6,236)		(2,634)		(22,381)
Net change	176,508		288,960		(71,276)
Beginning of year	807,170		518,210		589,486
End of year	$	983,678	$	807,170	$	518,210

Certain information concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. We believe this information is essential for a proper understanding and assessment of the data presented.

The assumptions used to compute SMOG do not necessarily reflect our expectations of actual revenues to be derived from neither those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to difficulty inherent in predicting the future, variations from the expected production rate could result from factors outside of our control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized.

The December 31, 2018, future cash flows were computed by applying the unescalated 12-month average prices of $65.56 per barrel for oil, $37.68 per barrel for NGLs, and $3.10 per Mcf for natural gas (then adjusted for price differentials) relating to proved reserves and to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.

Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil, NGLs, and natural gas reserves at the end of the year, based on continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil, NGLs, and natural gas reserves less the tax basis of our properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to our proved oil, NGLs, and natural gas reserves.

Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur.